1. Field of the Invention
This invention relates to a method and system for recovering sulfur from sulfur-containing gaseous streams. In one aspect, this invention relates to a method and system for directly treating sour, contaminated gas streams. In one aspect, this invention relates to a method and system for treating amine offgas streams.
2. Description of Related Art
Conventional technology for removing H2S from natural gas and hydrocarbon process gas streams is to contact the process gas stream in a suitable mass transfer contacting device, usually a vessel fitted out with packing or contactor trays, for example valve trays with an amine solution at a specified strength of amine in water, usually 50% or less amine by weight, but dependent on the specific amine employed. Such amines absorb acidic gases, CO2, and H2S, and similar acidic components, although these are the acidic components usually found in significant concentrations, and forms a chemically bonded solution referred to as a rich or loaded amine. The rich or loaded amine is sent to be “stripped” or regenerated, usually by the application of heat from direct injection of steam into a second, separate amine contactor often referred to as the regenerator, stripper, or reboiler, but also by indirectly heating the rich solution in the reboiler. Inert gases or gases not containing acidic components, such as nitrogen, may also be added to such strippers to promote the dissociation of the chemically bonded acidic components or allow the reactions to occur at lower temperatures. Vacuum may also be applied. After sufficient exposure to conditions in the stripper, the now lean solution is cooled, usually by cross exchange with the feed to the stripper so as to minimize the required heat duty of the overall system. The lean amine is then returned to the absorber. The offgases from the stripper are sent to a sulfur recovery unit, most often a Claus plant in which some of the gas is burned with air to create approximately 2:1 H2S/SO2 ratio in the gas at a temperature above 2500° F., resulting in the reaction 2H2S+SO2=3S+2H2O occurring in the gas phase. The gas is then cooled, resulting in separation of up to about 70% of the sulfur in the feed as elemental sulfur in the liquid phase. The gas is reheated and passed over a catalyst at 600° F. or thereabouts, resulting in the formation of additional elemental sulfur. The gas is then cooled again, resulting in further elemental sulfur recovery. This is repeated in a total of 3 or 4 such catalytic Claus reactors until about 97% of the sulfur has been removed. Further removal is limited by equilibrium and if additional sulfur needs to be removed, all of the sulfur containing compounds are converted to H2S over a catalyst with added H2-rich gas, further treated with a special amine to remove the H2S preferentially to other gases present, and such H2S-rich gas is recycled to the Claus process. By such means, in excess of 99% of the sulfur can be removed. The steps subsequent to the Claus reactors and condensers are referred to as off gas treating processes and “tail gas” treating processes. Various enhancements to these processes exist to achieve even higher recoveries when required. For smaller tonnages of sulfur in the feed gas, on the order of 20 tons per day or less, liquid redox processes such as LO-CAT or Stretford, or the CrystaSulf process, may instead be employed more economically. For even smaller tonnages on the order of 100 lbs/day or less, absorbent beds of iron containing materials or caustic impregnated carbon or zinc oxide, or liquid filled beds of triazine “scavengers” or other chemicals or caustic may be used at lower system cost than the liquid redox type processes.
When various streams need to be treated separately to achieve varying sulfur removals, for example if such streams are needed in a complex process, separate amine absorbers may be used to achieve the varying requirements and at various operating pressures, temperatures, and flowrates, but if desired, and for cost efficiency, the rich amine resulting from such absorbers can be commingled and brought to a common regenerator for removal of the absorbed components. Such common removed offgases or acid gases can then be sent to a common sulfur recovery unit, again for economy and cost efficiency reasons. For example, the maximum size of a Claus sulfur recovery unit is on the order of 3000 tons per day of sulfur. This commingling of streams to a common Claus unit takes advantage of well known economy of scale principles. The same principles apply to the desire to use a common regenerator for the amine streams.
The University of California Sulfur Recovery Process, hereinafter referred to as the UCSRP, either directly treats sour, contaminated gas streams (referred to herein as UCSRP-HP (high pressure)) or amine offgas (referred to herein as UCSRP-LP (low pressure)) or similar gas in a reactor/contactor vessel at conditions where the reaction of 2H2S+SO2=3S+2H2O takes place in the presence of a catalyst at temperatures above the melting point of sulfur. See, for example, U.S. Pat. No. 6,645,459, U.S. Pat. No. 6,495,117, and U.S. Pat. No. 7,281,393. The process is a solvent-based process for reacting excess H2S and SO2 in a liquid-phase reactor vessel containing a mixture of an organic solution, referred to herein as an “UCSRP solvent” or “UCSRP solution”, and a catalyst which catalyzes the reaction at a temperature above the melting point of sulfur. UCSRP solvents are physical solvents of moderate to low viscosity which are chemically inert to the reactants, products or other components with which they come in contact. UCSRP solvents readily absorb H2S and SO2, preferably do not form an azeotrope with water, are chemically inert to the reactants, liquid sulfur and water, and have limited mutual solubility with liquid sulfur. Preferred UCSRP solvents are those derived from ethylene oxide or propylene oxide by a ring-opening reaction with a co-reactant having an active hydrogen, provided that the resulting solvent is inert with respect to both sulfur and SO2. Typical of such solvents are the polyglycol monoethers and many diethers of both ethylene and propylene glycol. Examples are glycols and glycol ethers derived from ethylene oxide or propylene oxide, particularly ethers of ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, propylene glycol, dipropylene glycol, tripropylene glycol, and tetrapropylene glycol. Specific examples are monomethyl, dimethyl, monoethyl, and diethyl ethers of these glycols. Additional UCSRP solvents are various trialkyl and alkyldialkanol amines, such as triethyl amine and methyl diethanol amine, and liquid alkyl and aryl quaternary ammonium salts. Preferred catalysts for use in the UCSRP are tertiary amines, particularly lower alkyl-substituted tertiary amines, and aryl-substituted tertiary amines, including those in which the amine nitrogen is an aromatic ring atom.
Conventional processes for removing H2S and other sulfur-containing gases, e.g. COS, SO2, and other gases from process streams containing such gases in chemical plants, heavy oil upgrade (tar sands) facilities, refineries, and coal gasification and similar facilities while simultaneously converting the removed sulfur-containing gases to elemental sulfur are significant capital and operating cost components of such plants. Application of the UCSRP may be advantageous by reducing the capital and operating costs for H2S and other sulfur compound removal and conversion to elemental sulfur, as compared with other available technologies such as amine plus Claus plus off gas treating. Published studies show cost savings up to 40% in capital and operating costs for replacing only the Claus and off gas treating processes.
Benefits of using the UCSRP are exemplified in syncrude upgrading processes such as are practiced in oil sands deposits in various parts of the world in which various hydrotreating processes, as shown in FIG. 1, are employed on crude fractions resulting from the distillation of raw syncrude such as gas oil, diesel, and naphtha fractions. The offgases of hydrotreating operation 10 contain significant amounts of H2S and unconverted H2 and it is required to recycle the unconverted H2. This offgas is typically processed in an amine absorber 11 for the removal of H2S and is located in the hydrotreating process area. The rich amine resulting from the hydrotreating of several different crude fractions is sent to a common amine regenerator 12 located in the acid gas process area, and the amine offgases (acid gas) from such amine regenerator is then sent to conventional sulfur recovery units 13 such as Claus plants with tail gas treating as necessary as well as other technologies for acid gas sulfur recovery known to those skilled in the art. The UCSRP can eliminate the need for such regenerator and sulfur recovery/tail gas treating steps by replacing these process steps with the steps of the UCSRP, and even greater savings may be realized by substitution of the amine plant and regenerator with the UCSRP. Although using the UCSRP is straightforward when the gas stream undergoing processing is treated directly, such is not the case with other streams. For example, an amine plant may preferentially be used to treat one or more streams to specification where use of the UCSRP for direct treatment of the stream(s) would not be able to meet process specifications due, for example, to incompatibility of the process stream with the required temperature of the UCSRP or the high vapor pressure of the solvent used in the UCSRP, or because other components not removed by the UCSRP are desired to be removed simultaneously with the acidic H2S and other sulfur compounds, unacceptable co-absorption of higher hydrocarbons, and for other reasons known to those skilled in the art. In that event, the acid gas from the regeneration of the amine would be available to the UCSRP, but this does not afford the opportunity for additional savings of applying the UCSRP to a high-pressure process stream directly, which use enables eliminating the amine plant and the associated regenerator, and the associated high process steam demand for the regenerator, and at little incremental cost to the UCSRP applied solely to the amine acid gas offgas.